Well completion method and fluid loss control composition

ABSTRACT

Polymers used to prevent fluid loss from boreholes may be eliminated after a predetermined time by including with the polymer composition halogen-substituted organic acids or their salt derivatives. These components hydrolyze, releasing hydrogen-halogen acids which break down the polymers within the wellbore or formation.

FIELD OF THE INVENTION

This invention relates to an improved well completion method and to animproved fluid loss composition comprising polymers wherein the polymersare broken by delayed release of acids.

BACKGROUND OF THE INVENTION

Wellbore holes for production of oil and gas from subterraneanformations are typically completed by placement of a casing, cementingof the casing, and then perforating the casing to provide communicationbetween the formation and the inside of the casing. When the formationis a poorly consolidated formation, the perforating is followed byinsertion of a wire-wrapped screen and a gravel packing between thescreen and the inside of the casing. A production tubing is theninserted along with packers, pumps or other artificial lift devices asrequired to produce fluids from the wellbore.

Temporarily controlling permeability at the borehole surfaces iscritical during this completion process. While drilling is proceeding,and throughout the completion process, the hydrostatic pressure of thefluids within the borehole is maintained above the formation pressures.This prevents formation fluids from entering the borehole, displacingthe drilling fluid with less dense liquids and resulting in a "kick" ora blow-out. The loss of drilling fluids into the formation is controlledby fluid loss control additives. These additives cause a cake to beformed at the borehole wall which provides a low permeability barrier.This cake keeps the drilling fluids within the borehole in spite of thefluids within the borehole being at pressures greater than the formationpressures. During drilling this barrier generally does not have to beremovable. But when a potential oil or gas producing formation is beingdrilled, it is desirable to have a barrier which is removable.

After the borehole is drilled through the target formations, casings areset and cemented into place. The casing is then perforated, usually byexplosive charges which send projectiles from a gun within the casingthrough the casing and into the formation. These perforations serve asconduits for formation fluids to flow into the borehole when productioncommences. Until the well completion is finished, fluid loss into theseperforations must be minimized in order to prevent damage to formationpermeability. This fluid loss must be controlled by a means which doesnot inhibit formation fluids from entering the casing via theperforations when production commences.

To provide a fluid loss control which can be removed when the need forit is eliminated, liquid biopolymers, natural polymers and theirderivatives are typically utilized. Biopolymers include polysaccharides,and xanthan gum. Natural polymers and their derivatives include starch,carboxymethylcellulose (CMC), low molecular weight hydroxyethylcellulose (HEC), and carboxymethylhydroxyethyl cellulose (CMHEC). Thesepolymers are typically removed by flushing the borehole with acidiccompounds. Acids degrade the polymers and permit removal of the barrier.These polymers may be used in conjunction with the salt granules. Saltgranules, by themselves, generally do not form a sufficient barrier, butin conjunction with a biopolymer such as starch, are very effective.

The post-flush with acid can degrade polymers which come into contactwith the post-flush, but it is difficult to contact a significantportion of the polymer barrier with the post-flush. Once a portion ofthe barrier is degraded, the fluids will flow into the formation fromthe break in the barrier. Significant portions of the barriers arebypassed unless the post-flush is continued for an extended period.Extending this post flush for a long period is undesirable due to thecost, delay, and the acids which are then produced from the wellbore asproduction begins.

It would be preferable to have a polymer breaker which could begenerated from an inert precursor, the precursor being presentthroughout the barrier, and generating the polymer breaker insignificant quantities when the barrier is no longer needed. Manycompounds which hydrolyze to form acids, such as esters, do so at rateswhich significantly decrease at even slightly acidic pHs. It would befurther advantageous to have a precursor which degraded at predictablerates which did not vary significantly with pH. It would also beadvantageous to have such a precursor which is water soluble. A solublebreaker would not be susceptible to physical separation from theeffective portion of the fluid loss barrier. Further, a soluble breakercould be present in both the initial fluid loss composition, andsubsequent wellbore fluids to ensure that the fluid loss barrier istotally exposed to the breaker.

It is therefore an object of the present invention to provide a wellcompletion method and a fluid loss control composition wherein aneffective fluid loss barrier is established from an aqueous mixture ofpolymers which contains soluble precursors to polymer breakers. It is afurther object to provide such a method and composition wherein therelease of polymer breakers from the precursors is not strongly pHdependent. It is a further object to provide such a method andcomposition wherein the fluid loss barrier is effectively removed,resulting in a formation permeability in the vicinity of theperforations which is not reduced by remnants of the fluid losscomposition.

SUMMARY OF THE INVENTION

These and other objects of the present invention are achieved by aprocess comprising the steps of:

a) determining the concentration of a halogen-substituted organic acidor a salt of a halogen-substituted organic acid required to decrease themolecular weight of the polymer to an extent where the polymer is not aneffective fluid loss control agent under reservoir conditions after aperiod of time;

b) preparing an aqueous-based mixture of an amount of the polymereffective for fluid loss control and the required concentration of thehalogen-substituted organic acid or halogen-substituted organic acidsalt;

c) injecting the aqueous-based mixture into the wellbore; and

d) spotting the aqueous-based mixture in a region of the wellbore fromwhich fluid loss is to be controlled.

The fluid loss composition of this invention can effectively controlfluid loss for a predetermined time period without permanently reducingpermeability in the region of the wellbore where fluid loss is to becontrolled. Such temporary control is needed after perforation of thecasing and formation, and after gravel is placed in a gravel-packingoperation. Because the regions within which fluid loss needs to becontrolled are also the regions from which the formation will beproduced into the wellbore, it is important to temporary control offluid loss without permanently reducing permeability.

The halogen-substituted organic acid hydrolyzes in the presence of waterto form hydrogen-halogen (a strong acid) and an alcohol-substitutedorganic acid. Salt functionality increases the water solubility of thisacid precursor, thereby allowing the precursor to be dispersedthroughout the polymer barrier and is therefore preferred. Thehydrogen-halogen acid generated will degrade the polymer in a controlledmanner, destroying water-loss barrier after it has served its purpose.

DETAILED DESCRIPTION OF THE INVENTION

Polymers which are useful as fluid loss additives are well known. Any ofthese polymers may be utilized in the practice of the present invention.These polymers include, but are not limited to, polysaccharides,starches, starch derivatives, hydropropyl guar, guars, xanthan gum,carboxymethylcellulose (CMC), low molecular weight hydroxyethylcellulose (HEC), carboxymethylhydroxyethyl cellulose (CMHEC), sodiumacrylate and crosslinked derivatives of the above. Effectiveconcentrations of each are known, and depend upon such variables asporosity, permeability and temperature of the formation. Generally, from10 to 200 pounds per thousand gallons of solution of these polymers areutilized.

Graded salt fluid loss pills are also known. These graded salt pillstypically contain a starch or a starch derivative and a polymer, e.g.HEC or xanthan gum. The present invention can also be utilized withthese pills. The breakers of this invention break down the starches andthe polymers, and water then invades the barrier, dissolving the salt.

The polymers are generally prepared in a separate batch of completionfluids, and then injected into a work string where they flow to bottomof the wellbore, and then out of the work string and into the annulusbetween the work string and the casing or wellbore. This batch ofpolymers is typically referred to as a "pill." The pill is typicallypushed by injection of other completion fluids behind the pill to aposition within the wellbore which is immediately above a portion of theformation where fluid loss is suspected. Injection of fluids into thewellbore is then stopped, and fluid loss will then move the pill towardthe fluid loss location. Positioning the pill in a manner such as thisis often referred to as "spotting" the pill. The polymers then form abarrier near the wellbore surface. This barrier significantly reducesfluid flow into the formation.

This fluid loss barrier must be a temporary barrier when fluids aregoing to be produced from the portion of the formation being treated toreduce fluid loss. Formation fluids are typically to be produced fromformations treated to control fluid loss after perforating, and aftergravel packing operations.

The halogen-substituted organic acid of this invention will hydrolyzewhen contacted with water to form hydrogen halogen andalcohol-substituted organic acid salts. Salt functionality renders thisacid precursor more water soluble than an acid functionality, andprovides a higher initial pH. Salt derivatives are therefore preferred.Acceptable halogen-substituted organic acids include: 3-iodobenzoicacid, 2-iodobenzoic acid, 2-chloroethanesulphonic acid,2-chloro-3,5-dinitrobenzoic acid, dichloroacetic acid, iodoacetic acid,monochloroacetic acid, 2-chloroacetamide, succinimide, 2-bromobenzoicacid, bromoacetic acid, 2-chloropropionic acid, 3-chloropropionic acid,3-bromopropionic acid, 3-chlorobutyric acid, and maleimide.

Halogen-substituted organic acid or their salt derivatives having fromone to three carbons are preferred due to their greater watersolubility.

Sodium salts of the halogen-substituted organic acids are most preferreddue to the relative availability of the sodium salt derivatives, butgenerally any monovalent metal cations will be sufficient. Potassium andammonium salts along with the sodium salts are preferred.

The cost of the fluid loss treatment can be minimized by optimizing thepolymer and breaker precursor to the reservoir conditions and the lengthof time the fluid loss treatment needs to be effective. Utilization of abreaker precursor with a half life which is too short in relation to thedesired length of time for the fluid loss treatment and the reservoirtemperature will result in a larger amount of biopolymer being required.

Mono halogen-substituted organic acid salts generally have longer halflives than higher substituted organic acid salts do at the sametemperatures and pHs. Higher carbon number halogenated organic acidsalts have shorter half lives than equivalent lower carbon numbermolecules. The position of the halogen on the hydrocarbon chain alsosignificantly affects the half life of the halogen-substituted organicacid salt. For example, 3-chloropropionic acid sodium salt at 141° F.and a pH of 7 and has a half life of about 16 hours, whereas2-chloropropionic acid sodium salt at this temperature and pH has a halflife of about 40 hours.

A basic material may optionally be included with the aqueous mixture ofthis invention. The inclusion of a basic material in the fluid losscomposition reacts with the earlier generated acids, thus preventingthem from significantly affecting the biopolymer barrier. This canresult in a more abrupt release of acid when the basic material isconsumed and converted to salt.

Acceptable amounts and types of fluid loss polymers are determined bymethods well known in the art.

The performance of specific polymers and halogen-substituted organicacid salts can be predicted by measuring the decline in constantshear-rate viscosity as a function of time at reservoir conditions.Although the constant shear-rate viscosity is not a direct measurementof fluid loss control capability, it is reflective of the rate ofdegradation of the polymers. It is therefore a good predictor of thetime required to break the polymers and eliminate the effective fluidloss barrier.

The time period for which the fluid loss barrier will be required to beeffective will vary considerably between applications. Generally, ingravel-packing operations, at least one "round trip" time is required. Around trip time is the time needed to retrieve equipment (e.g.,perforating gun) from the bottom of the hole, and go back to the bottomof the hole with new equipment (e.g., gravel pack screen). Typically,about one hour per 1,000 feet of depth is required to pull or place workstrings. Most typically, the time period for which fluid loss controlwill be required will be between about 7 and about 200 hours.

To ensure thorough removal of the polymer barrier, acid components maybe injected into the formation after the fluid loss barrier is notneeded to finish breaking the biopolymer barrier. This flush will besignificantly more effective than the post-flush of the prior artpolymer removal step because the permeability of the entire barrier issignificantly increased by the acids generated by the breaker precursorsof this invention. Such an acid post-flush is preferably initiated afterthe need for the fluid loss barrier no longer exists, i.e., the timeperiod for which the fluid loss control is to be effective has expired.

Additional breaker precursor can also be injected into the wellborefollowing the initial injection of the fluid loss control pill. Thisensures that the fluids in the vicinity of the fluid loss barrier formedby the polymers contains the acids being generated by the precursor.Because the fluids injected into the wellbore with the polymers aregenerally immobilized with the barrier just within the formation,following of the pill with additional precursor is not generallyrequired.

The following examples are given to exemplify the invention, but do notlimit the invention.

EXAMPLES

Two compositions of different biopolymers were combined with a 2. molarsolution of mono chloroacetic acid sodium salt in water. The aqueousmixtures were then subjected to a constant 0.87 1/sec. shear rate andviscosity measurements were taken. The biopolymers were xanthan("SF-XA"), and succinoglycan ("SF-S"). The two tests were run at 200° F.and 190° F., respectively. The viscosities measured for thecompositions, both with and without breakers, are listed below in Table1.

                  TABLE 1                                                         ______________________________________                                              SF-XA     SF-XA           SF-S   SF-S                                         With      Without         With   Without                                      Breaker   Breaker         Breaker                                                                              Breaker                                Time  @         @        Time   @      @                                      Hours 200° F.                                                                          200° F.                                                                         Hours  190° F.                                                                       190° F.                         ______________________________________                                         0    3165      3571                                                           2    2972      3189      1     2106   2152                                    4    2798      3132      3     2005   2118                                    6    2652      3030      5     1943   2082                                    8    2473      2964      7     1897   2043                                   10    1794      2923      9     1849   2048                                   12    1419      2835     11     1781   2047                                   14     954      2792     13     1703   2040                                   16     486      2719     15     1604   2016                                   18     305      2640     17     1498   2016                                   20     205      2581     19     1451   2017                                   22     158      2487     21     1344   1998                                   26     117      2293     23     1321   2018                                   30     107      2167     25     1135   2024                                   34     95       1977     27      806   2051                                   38     96       1734     30      365   2006                                   44     97       1468     35      97    1993                                   50     91       1219     40      21    1937                                   56     93       1046                                                          ______________________________________                                    

From Table 1 it can be seen that inclusion of the breaker precursorsresults in a precipitious drop in biopolymer mixture viscosity after aperiod of relatively high viscosity. The aqueous biopolymer-containingmixture of the present invention is formulated so that this precipitiousdrop in viscosity occurs just after the time period for which the fluidloss barrier is to be effective expires.

I claim:
 1. A process to control fluid loss from a wellbore for a controlled period of time utilizing a polymer fluid loss control agent comprising:a) determining the concentration of a halogen-substituted organic acid salt required to decrease the molecular weight of the polymer to an extent where the polymer is not an effective fluid loss control agent under reservoir conditions after a period of time; b) preparing an aqueous-based mixture of an amount of the polymer effective for fluid loss control and the required concentration of the halogen-substituted organic acid or halogen-substituted organic acid salt; c) injecting the aqueous-based mixture into the wellbore; and d) spotting the aqueous-based mixture in a region of the wellbore from which fluid loss is to be controlled.
 2. The process of claim 1 wherein the aqueous-based mixture is spotted to a location, above a location where fluid loss is suspected to be occurring or is anticipated.
 3. The process of claim 1 wherein the aqueous-based mixture is injected after a casing within the wellbore is perforated.
 4. The process of claim 1 wherein the aqueous-based mixture is injected after a gravel pack is placed within the wellbore.
 5. The process of claim 1 wherein the polymer is selected from the group consisting of succinoglycan, hydroxy ethyl cellulose, xanthan gum, starch and starch derivatives, polysaccharides, carboxymethylcellulose, hydroypropyl guar, guars, and cross-linked derivatives of the above.
 6. The process of claim 1 wherein the organic acid portion of the halogen-substituted organic acid is a one-to-three-carbon organic acid component.
 7. The process of claim 6 wherein the halogen-substituted organic acid is a halogen-substituted carboxylic acid.
 8. The process of claim 1 wherein the halogen-substituted organic acid salt is a chloroacetic acid sodium salt.
 9. The process of claim 1 wherein the period of time is within the range of about 7 to about 200 hours.
 10. The process of claim 1 wherein additional halogen-substituted organic acid or halogen-substituted organic acid salt is included within the wellbore fluids injected into the wellbore after the aqueous-based mixture is injected into the wellbore.
 11. The process of claim 1 wherein additional acidic components are injected into the wellbore after the period of time.
 12. The process of claim 1 wherein the aqueous mixture further comprises an amount of a base capable of neutralizing acid generated by the halogen-substituted organic acid salt prior to the end of the controlled period of time.
 13. The process of claim 1 wherein the aqueous mixture comprises salt crystals.
 14. The process of claim 13 wherein the polymer is selected from the group consisting of starch, starch derivative, hydroxyethyl cellulose, xanthan gum and combinations thereof. 